Many crude oils processed by refineries contain varying amounts of nitrogen and sulfur compounds. During the refining process, it frequently becomes necessary to remove such compounds because they impart undesired properties such as disagreeable odor, corrosivity, poor color, and the like, to saleable products. In addition, the compounds may have deleterious effects in various catalytic refining processes applied to oils.
Various processes have been devised for removing the nitrogen and sulfur compounds from oils, one common process being treatment with hydrogen wherein the nitrogen and sulfur compounds are converted to ammonia (NH.sub.3) and hydrogen sulfide (H.sub.2 S). Such conversion is usually promoted by use of elevated temperatures and pressures in the presence of hydrogenation catalysts. Reactions of the nitrogen and sulfur compounds with hydrogen to form NH.sub.3 and H.sub.2 S can also occur in other processes such as thermal and catalytic cracking, reforming, and hydrocracking, which are not specifically designed for such purpose. There are thus produced various effluent gas streams containing NH.sub.3 and H.sub.2 S.
The removal of some NH.sub.3 and H.sub.2 S from such effluent streams may be accomplished by scrubbing with water, preferably at elevated pressure and low temperature. To obtain the desired extent of removal, however, it is often necessary to use a rather large amount of water so that a dilute aqueous solution of ammonia and H.sub.2 S is formed. With increasing urbanization and concentration of industrial complexes, the situation is rapidly developing where pollution of water near population centers with such compounds is not desirable. The refiner thus may be compelled to remove the NH.sub.3 and H.sub.2 S from such waters in, for example, a sour water stripper resulting in a need to then dispose of the resulting NH.sub.3 and H.sub.2 S vapor.
In many cases, it is desirable to use the hydrogen sulfide present in such mixtures as feed to a sulfur recovery operation; however, the presence of ammonia can give rise to complications such as, for example, the formation of ammonium sulfite and ammonium sulfate in a sulfur recovery system where cooling occurs, resulting in fouling of the catalyst and plugging of the equipment. While processes exist which are capable of effecting separation of ammonia from hydrogen sulfide, such methods require a large capital investment and the operating costs are relatively high.
In conventional sulfur recovery operations in which the feed gas typically contains more than 50 mole percent hydrogen sulfide, all of the acid gas feed is introduced into a noncatalytic combustion zone or furnace together with enough oxygen ordinarily in the form of air to convert about one-third of the hydrogen sulfide into sulfur dioxide. In the case of ammonia-contaminated hydrogen sulfide streams, even when sufficient additional air to burn ammonia is added, the hydrogen sulfide present competes with the ammonia for the extra oxygen, resulting oftentimes in incomplete combustion of the ammonia. The presence of excessive concentrations of ammonia in the combustion products creates conditions downstream for the formation of ammonium salts, such as, for example, those mentioned above, in the condenser tubes, the tail gas scrubber system, separator seal legs, etc. The failure of oxygen to effect complete combustion was borne out in tests performed where ammonia was purposely added to the feed. In a plant test, ammonia was present in the feed to the extent of about 23 volume percent or 230,000 ppm (dry basis). A conversion of about 99.9% was achieved in the furnace and the effluent had an ammonia concentration of about 200 ppm. In a second case (a laboratory run in which the feed contained 15 volume percent (dry basis) NH.sub.3), the ammonia conversion exceeded 99.9% and the furnace effluent had an ammonia concentration of about 35 ppm.
We have found in the past that one preferred method for handling a gas stream which contains ammonia in a conventional sulfur plant is to feed all of the ammonia-containing gas to the burner of the furnace together with a portion of ammonia-free acid gas, while the remaining ammonia-free acid gas is fed to a downstream point. This makes it possible to achieve ammonia conversions in a plant furnace as high as indicated above for the laboratory test. In plant units with this design which do not have a tail gas clean-up unit, the resulting ammonia at low concentration has passed through the condensers and catalyst beds without causing problems. However, as discussed below, even this low concentration of ammonia can cause problems in tail gas clean-up units.
Moreover, sulfur plants are employed to process H.sub.2 S-containing gases from various types of industrial operations other than petroleum refining. Hydrogen sulfide from certain operations may contain nitrogen-containing compounds which can form ammonia in the sulfur plant noncatalytic combustion zone or thermal reactor. An example is the hydrogen sulfide which is recovered from coal gas, also known as coke-oven gas, which is formed from destructive distillation of bituminous coal. This gas often contains hydrogen cyanide (HCN) which is partially combusted in the thermal reactor but may be partially hydrolyzed therein to form gaseous ammonia. We have found that the combustion system can be designed to result in a high efficiency for combustion of HCN, with the ammonia concentration in the effluent being low enough that it does not cause a problem in the condensers and catalytic reactors of a conventional sulfur plant; however, as discussed below, it may cause a problem in certain tail gas clean-up units.
In order to comply with the regulations of the Environmental Protection Agency, many sulfur plants now in operation of being designed employ some type of tail gas treating process to minimize the amount of sulfur compounds ultimately discharged into the atmosphere. One such treating process is known as the Cold Bed Adsorption (CBA) method which involves taking the sulfur plant tail gas and alternately feeding it to one of at least two catalytic reactors, at least one reactor being operated at about 260.degree. F. to 300.degree. F. on the adsorption cycle (for example, about 18 hours), allowing H.sub.2 S and SO.sub.2 to further react at this relatively low temperature to produce free sulfur, while at least one other reactor is undergoing a regeneration cycle of, for example, about 12 hours followed by a cooling cycle of, for example, about 6 hours. In regeneration of, for example, the CBA catalyst beds, adsorbed sulfur is driven off the catalyst by the use, for example, of hot (650.degree. F.) effluent from the first reactor in the sulfur plant. The CBA process is described in detail in U.S. Pat. No. 4,035,474. When NH.sub.3 is present in the feed stream to the sulfur plant, however, a certain amount of NH.sub.3 remains in the sulfur plant tail gas, i.e., the feed to the tail gas clean-up process, for example, the CBA unit. Ammonia present in the feed to the tail gas clean up process can react with SO.sub.2 present to form ammonium sulfite which is adsorbed on the catalyst during adsorption cycle. Later in the regeneration cycle when the catalyst is heated with regeneration gas, NH.sub.3 is liberated. The liberated NH.sub.3 can return in the regeneration gas to pass through the second Claus reactor and thence to the low temperature reactor in adsorption cycle, where it can be again adsorbed on the catalyst. Thus the ammonia can be repetitively adsorbed on the first catalyst bed, then desorbed from the first bed but readsorbed on the second bed, then desorbed from the second but readsorbed on the first in the next cycle, and so forth. Continued operation in this manner can eventually cause the deposition of ammonium salts on the catalyst to be excessive and result in deactivation and plugging of the catalyst.